The background description includes information that may be useful in understanding the present invention. It is not an admission that any of the information provided herein is prior art or relevant to the presently claimed invention, or that any publication specifically or implicitly referenced is prior art.
Acid gas removal from various gas streams, especially removal of CO2 from natural gas streams has become an increasingly important process as the sweet gas reservoirs are being depleted and the high CO2 content fields are being developed. There are relatively large natural gas resources untapped in the world (e.g., Alaska, Continental North America, Norway, Southeast Asia, South China Sea, and Gulf of Mexico) that contain very high levels of CO2, often ranging from 15% to 60 mol %. Where CO2 is used for enhanced oil recovery (EOR), CO2 content in the fields is gradually increasing, and further field development must then include CO2 removal that can handle variable CO2 content gases.
Typically, gas plants are designed to meet pipeline gas transportation specifications on inerts, sulfur, hydrocarbons, and water dewpoint requirements and not designed to handle high CO2 content gases (e.g., 50 mol % or higher). Such processing facilities include amine treating, glycol dehydration, and hydrocarbon removal for processing low levels CO2 gases (5 mol % or less). Gas fields with high CO2 content are often considered uneconomical as technologies for high CO2 removal or variable CO2 removal are considered difficult; and consequently such high CO2 gas fields remained undeveloped. To overcome at least some of the disadvantages associated with gas production having high CO2 content, numerous CO2 removal processes have been developed which can be categorized into physical and chemical processes, wherein the choice of the appropriate gas treatment predominantly depends on the gas composition, feed gas pressure, product gas specifications and location of the plants (onshore or offshore).
For example, in one category membrane separators are used to separate acid gases from the natural gas streams using preferential diffusion of CO2 through membrane elements. A typical membrane system has a pre-treatment skid and a series of membrane modules. Membrane systems are relatively compact and simple to operate and are often used to treat low volume of high pressure CO2 gases, especially in offshore applications. However, membrane elements are prone to fouling and material degradation from gas contaminants and therefore must be monitored and periodically replaced. While initial capital outlay may be lower than with other processes, replacement costs of the membranes add up over the life of the plant. In terms of performance, single stage membrane separators are relatively non-selective and often produce a CO2 waste stream with a high hydrocarbon content, which may not meet environmental permits on greenhouse gas. Additional processing equipment may be used to improve the membrane performance (e.g., multiple stages of membrane separators with inter-stage recompression and recycle), however, such equipment will increase the cost and footprint of the system, rendering membrane separation economically unattractive.
In another category, a chemical solvent is employed that reacts with the acid gases to form a (typically non-covalent) complex. In processes involving a chemical reaction between the acid gas and the solvent, the feed gases are scrubbed with an alkaline salt solution of a weak inorganic acid (e.g., U.S. Pat. No. 3,563,695 to Benson), or with an alkaline solution of organic acids or bases (e.g., U.S. Pat. No. 2,177,068 to Hutchinson). All publications identified herein are incorporated by reference to the same extent as if each individual publication or patent application were specifically and individually indicated to be incorporated by reference. Where a definition or use of a term in an incorporated reference is inconsistent or contrary to the definition of that term provided herein, the definition of that term provided herein applies and the definition of that term in the reference does not apply. One particular advantage of a chemical solvent system is that such systems are quite selective and typically do not absorb hydrocarbons to any significant degrees. Furthermore, the chemical solvent systems, such as promoted or activated MDEA, can produce a product gas with CO2 content in the low ppm range which is required for LNG production.
However, while use of chemical solvent (e.g. amine) systems may be advantageous, particularly in treating low CO2 content gases, there are unsurmountable difficulties when applied to treat high CO2 fields. Amine systems operate by the principle of chemical reaction equilibrium and not influenced by pressure to any significant extent. Even at high CO2 partial pressure, the CO2 rich loading does not change much. In other words, the heat required for amine regeneration is proportional to the amount of CO2 in the feed gases. Thus, as the CO2 content in the field increases, additional amine units must be added to meet sales gas specification on CO2. Even with activated or promoted tertiary amine such as MDEA, the heat requirement for solvent regeneration is significant for high CO2 content gases, which may consume significant amounts of the treated gas for heating, making such development once again uneconomical. Furthermore, the amine processes typically operate at relatively high temperature such that equipment and piping are prone to failure from corrosion and foaming problems. Still further, chemical solvent systems typically include columns, heaters, air coolers, pumps, etc., all of which require frequent monitoring and maintenance. Yet another disadvantage of amine systems is that the treated gas and CO2 streams are saturated with water, which must be dried with a drying unit to meet pipeline specifications.
In yet another category, a physical solvent can be used for removal of high CO2 content gases. Unlike amine processes, physical solvent loading capacity increases with the acid gas partial pressure according to the principle of Henry's law. This principle also favors low absorption temperature as low temperature also increases the solvent loading, hence reducing solvent circulation. High partial pressure and low operating temperature tends to favor physical solvent operation. For example, methanol processes that operate at cryogenic temperature may be employed as a low-boiling organic physical solvent, as exemplified in U.S. Pat. No. 2,863,527 to Herbert et al. However, cryogenic refrigeration is very costly, and low temperature solvent also co-absorbs a significant amount of hydrocarbons, resulting in high hydrocarbons losses. Therefore, while the methanol process is common in syngas treating, they are rarely used in natural gas plants.
Alternatively, physical solvent process can be operated at slightly below ambient temperature to minimize hydrocarbon losses. For example, the Fluor Solvent Process using propylene carbonate as physical solvent can be employed as taught in U.S. Pat. Nos. 7,192,468; 7,424,808 and 7,637,987 to Mak, J. These processes, as shown in Prior Art FIG. 1, are in many cases efficient in removal of high CO2 feed gases and do not require heating as solvent regeneration is solely accomplished by flash regeneration. Mak's processes also employ the chilled flashed solvent to cool the absorber removing the CO2 heat of absorption. With such efficient configurations, refrigeration requirement by the physical solvent processes can be nearly or mostly eliminated. Nevertheless, there are limitations on these processes as they require a vacuum flash stage to produce the lean solvent which is energy intensive. Moreover, where vacuum stages are omitted, non-vacuum flash stages will not produce an ultralean solvent to meet stringent CO2 specifications. Such processes are acceptable as long as the CO2 specification in the product gas is 2 to 3% CO2, but would not meet CO2 content less than 500 ppmv, which may be required in the future to meet regulations on greenhouse gas emissions. Low CO2 content treated gas is also advantageous as the product can be used for blending with other high CO2 gases.
Therefore, it should be appreciated that most known solvent processes lack an efficient heat exchange integration configuration, and often require significant refrigeration and/or high solvent circulation, and sometimes require heat for solvent regeneration. In most or almost all of the known physical solvent processes, either heating or the use of a vacuum flash system must be applied for solvent regeneration. Even with significant fuel and power consumption, these processes cannot fully regenerate the solvent to an ultralean level that can be used to treat high CO2 feed gas to meet a low CO2 specification on carbon capture.
Thus, although various configurations and methods are known to remove CO2 from a feed gas, all or almost all of them suffer from one or more disadvantages. Therefore, there is still a need to provide methods and configurations for a flexible and innovative CO2 removal.